U.S. Incentives to Capture and Store CO 2
Fact sheet on the 45Q tax credit. 45Q was created in 2008 as a tax credit to incentivize the development of carbon capture, utilization, and storage (CCUS) projects.
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U.S. Incentives to Capture and Store CO 2
Fact sheet on the 45Q tax credit. 45Q was created in 2008 as a tax credit to incentivize the development of carbon capture, utilization, and storage (CCUS) projects.
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Section 45Q
Fact sheet on the 45Q tax credit. 45Q was created in 2008 as a tax credit to incentivize the development of carbon capture, utilization, and storage (CCUS) projects.
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Front-End Engineering and Design: Project Tundra Carbon Capture System (Final Report)
As the next phase of Project Tundra, Minnkota Power Cooperative (MPC) completed a front-end engineering and design (FEED) study to install a post-combustion CO 2 capture system (CCS) at the MPC operated (Square Butte Electric Cooperative-owned) Milton R. Young Station (MRYS) Unit 2 (MRY2), a 477-MW power plant fueled by North Dakota lignite. The project team completed the FEED with Fluor’s Econamine FG Plus℠ (EFG+) technology and is taking the next steps leading up to start of construction. Team members included FEED technical lead Fluor Enterprises (Fluor); owner’s engineer and balance of plant (BOP) engineer Burns & McDonnell (BMcD); leading carbon capture consultants (David Greeson Consulting, Hunt International Energy Services); environmental consultants (AECOM, Agora Environmental), other BOP engineering consultants (Golder Associates, Nels); cost-share funding agency, the North Dakota Industrial Commission (NDIC); and the Energy & Environmental Research Center (EERC). Project Tundra’s goal is to implement carbon capture, utilization, and storage (CCUS) in North Dakota, while preserving the use of lignite. Future options could lead to revitalizing legacy oil fields and creating a new CO 2 enhanced oil recovery (EOR) industry. The topic of this report is the FEED study for the carbon dioxide capture portion of Project Tundra. Building on the findings of a pre-FEED study for MRY2, the key deliverables contained in this FEED study are: a) design, costing, and performance data needed to commence project financing activities; b) engineering and material balances required to file for all project permits; and c) a final project schedule. Based on the results of the previous pre-FEED study, MPC and its team evaluated two options to provide the large amount of steam needed to operate the CCS: 1) installation of new natural gas package boilers and a new pipeline to supply natural gas to the facility and 2) extraction of steam from the existing MRYS steam turbine generator. The FEED study was performed using the package boilers option, as it was deemed to have the lowest technical risk, overall cost, and cost uncertainty. A key feature of the design, however, was the mixing the natural gas boilers’ flue gas with the MRY2 flue gas. This increased the size of the CCS system. This design also enabled the tie-in of Unit 1 flue gas for times when Unit 2 is offline. The CCS was designed to capture a combined 12,978 short tons per day (STPD) of CO 2 from the flue gases produced by the existing MRY Unit 2 along with flue gas produced by the new boiler package within the CCS. The 12,978 STPD CO 2 capture is achieved by normally processing 100% of the total available MRY Unit 2 flue gas (considering full load operation) and 100% of the boiler package flue gas, then removing 90% of the CO 2 available from the processed flue gas streams.
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PCOR Partnership Atlas 6th Edition, Revised
The Plains CO 2 Reduction (PCOR) Partnership Atlas provides a profile of CO 2 sources and potential storage locations across the PCOR Partnership region. The revised sixth edition of the Atlas provides an up-to-date look at PCOR Partnership initiative activities, including additional regional characterization and updates on commercial projects. Additional background information on carbon capture, utilization, and storage (CCUS) is included to give a better understanding of how CCUS addresses concerns about climate change while allowing future energy needs to be met.
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Regional Geologic Cross Sections for Potential Storage and Containment Zones in the MRCSP Region
The Midwest Regional Carbon Sequestration Partnership (MRCSP) has incorporated the work of geologic research teams (Geoteams) in its regional characterization, project planning and carbon dioxide (CO 2 ) injection implementation work since the partnership was established by the U.S. Department of Energy (DOE) in 2003. Over this 16-year period, the cohort of Geoteams has grown from five to ten states and has contributed to the characterization of geologic sequestration opportunities, refinement of reservoir and seal data, and supported injection efforts through both predictive and post-injection assessments. Five geologic cross sections (labeled A through E) were constructed onshore across the parts of the MRCSP Region west of the Valley and Ridge Province, and one section (labeled F) was constructed beginning onshore in New Jersey and running eastward to offshore areas examined for carbon storage. Regional and local stratigraphic units were used in these cross sections to show current nomenclature as well as highlighting specific units/features pertinent to carbon capture, utilization and storage (CCUS) opportunities in the region. Each cross section uses 15 to 25 deep wells and other geologic information to illustrate the relative depth, thickness and location of rock units in the subsurface.
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Scaleup and Site-Specific Engineering Design for Global Thermostat Direct Air Capture Technology
The overall goal of the project is completion of an initial design of a commercial-scale, Carbon Capture, Utilization, and Storage Direct Air Capture (CCUS-DAC) plant design at three different sites that captures a net of at least 100,000 tonnes per year (TPY) carbon dioxide (CO 2 ) from the atmosphere and considers compression and conditioning of the captured CO 2 for purpose of pipeline transportation to different geological formation sites for deep well injection and underground storage. In addition to the leading system consisting of a scaled-up Global Thermostat DAC unit, overall plant design includes a combined Heat and Power (CHP) unit integrated with a conventional liquid amine-based carbon capture system (90% capture) and compression facilities. These are considered balance of plant (BOP) systems and are required to provide low carbon-intensity steam and power to the DAC process. A second approach involving provision of DAC units modified to directly capture emissions from the CHP unit was initially assessed as an alternative and it was determined to be less mature than considered approach and not included in the scaled-up plant design efforts. Three geographically diverse continental United States locations were selected to better understand the effect of local/regional ambient conditions on scaled-up DAC system performance and project costs: Bucks, Alabama (hot wet climate), Odessa, Texas (dry hot climate), and Goose Creek, Illinois (mid continental climate). The team focused on initial engineering design activities, including the development of project design criteria, initiation of site-specific studies and investigations, completion of DAC system process and equipment design, and definition of balance of plant (BOP) engineering. The purpose of the activities were to develop Technoeconomic Analysis (TEA), Life-Cycle Analysis (LCA), and Environmental, Health, and Safety (EH&S) analysis, and Business Case Analysis (BCA) to validate that the project engineering and scale-up plans of the DAC systems, at each of the three distinct case studies considered, are technically, economically, and environmentally feasible for commercial-scale operation.
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High-pressure CO 2 dissociation with nanosecond pulsed discharges
Herein we investigate the conversion of CO 2 into CO and O 2 with nanosecond repetitively pulsed (NRP) discharges in a high-pressure batch reactor. Stable discharges are obtained at up to 12 bar. By-products are measured with gas chromatography. The energy efficiency is determined for a range of processing times, pulse energy, and fill pressures. It is only weakly sensitive to the plasma operating parameters, i.e the extent of CO 2 conversion is almost linearly-dependent on the specific energy invested. A conversion rate as high as 14% is achieved with an energy efficiency of 23%. For long processing times, saturation in the yield and a drop in efficiency are observed, due to the increasing role of three-body recombination reactions, as described by zero-dimensional detailed kinetic modeling. The modeling reveals the presence of three-stage kinetics between NRP pulses, controlled by electron-impact CO 2 dissociation, vibrational relaxation, and neutral elementary kinetics. Transport effects are shown to be important for CO 2 conversion at high pressures. For fill pressures beyond 10 bar, CO 2 may locally transit into supercritical states. The supercritical plasma kinetics may bypass atomic oxygen pathways and directly convert CO 2 into O 2 . This work provides a detailed analysis of plasma-based high-pressure CO 2 conversion, which is of great relevance to future large-scale sustainable carbon capture, utilization, and storage.
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Fracture Network Quantification for Enhanced Reservoir Characterization in CO2 Storage Sites
Presentation slides on “Fracture Network Quantification for Enhanced Reservoir Characterization in CO2 Storage Sites” for the CCUS 2025 conference held in Houston, Texas March 3-5, 2025. Accurate reservoir characterization is fundamental for the safe and efficient operation of carbon capture, utilization, and storage (CCUS) projects. This process is not only critical during initial site selection but also plays a key role in continuously updating reservoir geomodels throughout injection operations to effectively manage subsurface storage sites. Our primary objective is to develop a comprehensive understanding of fracture networks within CO2 injection reservoirs, which are critical for predicting the behavior of injected fluids, ensuring storage integrity post-injection, and mitigating risks such as leakage or induced seismicity.
artifical intelligence / machine learning (AI/ML)↗
FracML: A Machine Learning Based Tool to Quantify Reservoir Scale Fracture Network for CO2 Storage
Poster on “FRACML: A Machine Learning Based Tool to Quantify Reservoir Scale Fracture Network for CO2 Storage” for the CCUS 2025 conference held in Houston, Texas March 3-5, 2025. The accurate characterization of subsurface fracture networks is essential for the secure operation of carbon capture, utilization, and storage (CCUS) projects. A thorough understanding of the spatial distribution of subsurface faults and fractures is crucial for predicting CO2 plume evolution and minimizing risks such as potential leakage into overlying formations or induced seismicity. In this context, robust fracture network quantification plays a pivotal role in reservoir management, providing the data necessary to fine-tune operational parameters, and ensure the environmental and economic viability of CCUS projects. As part of the U.S. Department of Energy’s SMART (Science-informed Machine Learning for Accelerating Real-time Decisions in Subsurface Applications) initiative, we focused on the development and application of a machine learning-based tool (FRACML) designed to quantify and map fracture networks using real-world (non-synthetic) data from an active CO2 injection site. Our objective is to demonstrate the utility of this tool in improving operational efficiency and safety across CCUS sites.
artifical intelligence / machine learning (AI/ML)↗
Chemo‐mechanical Alterations Induced From CO 2 Injection in Carbonate‐Cemented Sandstone: An Experimental Study at 71 °C and 29 MPa
Abstract Carbon capture, utilization, and storage may lead to mechanical degradation of the subsurface reservoir from fluid‐rock interaction, which could lead to wellbore instability or reservoir compaction. To better understand potential relationship between mechanical degradation with various carbonate cement textures and compositions in sandstone reservoirs, six flow‐through experiments were conducted. Formation water (TDS = 5,390 mg/L) enriched with CO 2 flowed through two types of Pennsylvanian Morrow B Sandstone: an ankerite‐siderite‐cemented sandstone (disseminated cement texture) and a calcite‐cemented sandstone (poikilotopic cement texture). The experiments produced little change in permeability in the ankerite‐siderite‐cemented sandstone, but permeability increased up to more than 1 order of magnitude in the calcite‐cemented sandstone. Ultrasonic measurements and cylinder‐splitting tests (also known as Brazilian tests) suggested negligible mechanical degradation of the ankerite‐siderite‐cemented sandstone. Variable changes, with significant mechanical degradation in the static moduli, were observed in the calcite‐cemented sandstone. Thus, dissolution of the disseminated ankerite‐siderite cement (0.28–0.30%) had minimal impact on modifying the flow network and the mechanical integrity of the sandstone, whereas dissolution of the poikilotopic calcite cement (0.89–1.13%, quantified with fluid chemistry and visualized with X‐ray microcomputed tomography) impacted the mechanical strength of the sandstone by disconnecting framework grains. With the high water‐to‐rock mass ratios (7.3–8.2) and number of pore volumes (147–675) employed in these experiments, potential risks are most relevant to regions near injection wells. Ultimately, the chemo‐mechanical effects induced by CO 2 injection are strongly influenced by the cement texture and composition and the burial history of the reservoir rock.
Wu, Z.↗
Mechanistic insights to drive catalytic hydrogenation of formamide intermediates to methanol via deaminative hydrogenation
Amine-promoted hydrogenation of CO 2 to methanol typically proceeds via a formamide intermediate when amines are used as additives or if the hydrogenation is performed in carbon capture solvents. The catalysts used for the hydrogenation of the formamide intermediate dictate the selectivity of the products formed: 1) Deoxygenative hydrogenation (C–O bond cleavage) resulting in N-methylation of amine and deactivation of the solvent, 2) Deaminative hydrogenation (C–N bond cleavage) resulting in formation of methanol and regeneration of the solvent. To date, catalytic reductions of CO 2 with amine promoters suffer from poor selectively for methanol which we attribute to the limiting formamide intermediate, though to date, the conditions that favor C–N cleavage have yet to be fully understood. To better understand the reactivity of the formamide intermediates, a range of heterogenous catalysts were used to study the hydrogenation of formamide. Well-known gas phase CO 2 hydrogenation catalysts catalyze the hydrogenation of formamide to N-methyl product via C–O bond cleavage. However, the selectivity can be readily shifted to selective C–N bond cleavage by addition of an additive with sufficient basicity for both homogenous and heterogeneous catalytic systems. The base additive shifts the selectivity by deprotonating a hemiaminal intermediate formed in situ during the formamide hydrogenation. This prevents dehydration process leading to N-methylated product, which is a key capture solvent deactivation pathway that hinders amine use in carbon capture, utilization, and storage (CCUS). The findings from this study provide a roadmap on how to improve the selectivity of known heterogenous catalysts, enabling catalytic reduction of captured CO 2 to methanol.
37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
Active Seismoelectric Monitoring of CO 2 Injection
Conference presentation at Carbon Capture, Utilization, and Storage (CCUS) Conference 2024, Houston, Texas, March 11–13, 2024. We investigated the use of active seismoelectric monitoring (ASE) to determine its effectiveness in detecting CO 2 injected deep underground and as an additional monitoring option for carbon storage projects. The EERC performed an ASE survey in February of 2023 at Pennel oil field near Baker, Montana, as part of the U.S. Department of Energy-sponsored Williston Basin CO 2 Field Laboratory in conjunction with operating partner Denbury Inc. The field site is part of the Cedar Creek Anticline geologic structure, with CO 2 planned for injection into a stacked storage complex (SSC) in the Interlake Formation containing both a residual oil zone and a conventional reservoir. The objective was to test the ASE method’s ability to characterize baseline fluid distribution in both the near surface and the SSC prior to CO 2 injection.
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Quantitative Risk Assessment (Topical Report)
Carbon capture, utilization, and storage (CCUS) in geological formations plays a key role in mitigating anthropogenic CO 2 emissions and achieving the aggressive goal of net-zero greenhouse gas emissions. Quantitative risk assessment is crucial for ensuring the safety and reliability of geologic carbon storage (GCS) by evaluating CO 2 migration in subsurface, forecasting potential leakage and induced seismicity risks, and optimizing operational and monitoring plans. We present the use, progress, and research trends of risk assessment from the Southwest Regional Partnership on Carbon Sequestration (SWP) as an example of large-scale CCUS projects in North America. The information provided in this report can help readers understand the significance of risk and uncertainty assessment and apply them effectively in large-scale CCUS projects.
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North Dakota Integrated Carbon Storage Complex Feasibility Study. Final report
In spring 2017, the Energy & Environmental Research Center (EERC) initiated an effort to determine the feasibility of developing a commercial-scale CO 2 geologic storage complex able to store 50+ million tonnes (Mt) of CO 2 in central North Dakota safely, permanently, and economically. The objective was to fulfill the goals of the U.S. Department of Energy (DOE) Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Initiative and address technical and nontechnical challenges specific to commercial-scale deployment of a CO2 storage project. The findings clearly show that the concept of capturing CO 2 from a lignite-fired electrical generation facility in central North Dakota and safely and permanently storing the CO 2 in the deep subsurface is indeed technically, economically, and socially feasible. This project evaluated two study areas and their respective geologic storage complexes located adjacent to separate coal-fired facilities in North Dakota: the Basin Electric Power Cooperative (BEPC)-owned Great Plains Synfuels Plant (GPSP) and the Minnkota Power Cooperative (Minnkota)-owned Milton R. Young Station (MRYS). These locations, one with CO 2 capture in place and an existing CO 2 pipeline, are bolstered by progressive North Dakota pore space ownership and long-term liability laws. These elements and a motivated team created an ideal synergistic scenario for ensuring success of the CarbonSAFE Initiative and promoting North Dakota’s statewide vision for carbon management. The project included drilling two new geologic characterization wells, integrating an existing 3-D seismic survey, creating a geologic model subsequently used for injection simulation, a risk assessment, public outreach, and generating a site development plan based on results. In addition, the performance of select National Risk Assessment Partnership tools was evaluated. The geologic characterization wells were drilled ~5600 feet deep to the Broom Creek Formation; ~350 feet of core was retrieved from each well. The core included the Broom Creek (targeted injection zone) and a portion of the overlying Opeche Shale (seal). The Flemmer-1 well, west of Beulah, North Dakota, yielded 169 feet of sandstone. The BNI-1 well located south of Center, North Dakota, yielded 124 feet of sandstone. In each case, laboratory analysis of the sandstone showed permeability in the 300–1000-mD range, with porosity of 20%–30%. The Flemmer-1 well was sited within the boundaries of an existing 3-D seismic survey. Colocating the well with the seismic survey maximized the relationship between new and legacy data and developed a first-of-its-kind interpretation of the geologic fabric of the Broom Creek. Geologic characterization data were integrated into a 5544-mi 2 geocellular model that encompassed both new wells and stratigraphy from the surface to the Amsden Formation (underlying the Broom Creek). The model was later expanded vertically to include the deeper Black Island–Deadwood interval to examine its potential viability as a storage target. The geocellular model provided the foundation for dynamic simulation of CO 2 into the Broom Creek. Results of the simulation suggest that the Broom Creek could accept the DOE target rate of 2 Mt/yr of CO 2 into as few as two wells. To bracket the expected capture from MRYS, simulations were also investigated for a 4-Mt/yr rate near MRYS. Although more wells are needed (two additional), the Broom Creek still has the storage resource to accept the CO 2 at the increased rate. A risk assessment exercise was conducted to identify and assess technical and nontechnical risks that could prevent potential candidate storage complexes within the study area from serving as commercial storage sites. The assessment identified and evaluated six technical risk categories: 1) CO 2 injectivity, 2) storage capacity, 3) lateral migration of CO 2 , 4) lateral pressure propagation, 5) vertical migration of CO 2 or formation brine, and 6) induced seismicity. Following two rounds of analysis and scoring, no risks were determined to preclude continued efforts to develop carbon capture, utilization, and storage (CCUS) in central North Dakota. The risk assessment results will be used to guide future site characterization, modeling and simulation, and monitoring activities. A specific nontechnical strategic risk based on challenges that may be realized in amalgamation of pore space resulted in vertically expanding the geologic model to incorporate the potential for stacked storage in multiple saline reservoirs. By including the Black Island–Deadwood interval (the basal sedimentary reservoir in this region), the amalgamated areal extent could be reduced by as much as 45%. Working with a smaller geographic area reduces risks and costs associated with monitoring and pore space leasing. An economic evaluation incorporating capture; transport (<5 mi); Class VI wells; permitting; and monitoring, verification, and accounting suggests implementing commercial-scale CCUS is economically attractive if the federal tax benefits of 45Q are included. This is validated by Minnkota’s continued pursuit of CO 2 capture and geologic storage at MRYS through its Project Tundra initiative, indicating that there is a business case for CCUS in central North Dakota. Currently, North Dakota is the only state with underground injection control (UIC) Class VI primacy. Built into the North Dakota Century Code is a series of regulatory requirements that guide the process to obtain a Class VI CO 2 storage facility permit. As part of this project, a site development plan was compiled to assure compliance with North Dakota’s requirements to permit a commercial-scale CO 2 storage operation and includes a prospective time line encompassing a general breakdown of activities. In total, an estimated 30 months would be needed to execute the necessary steps to attain a North Dakota CO 2 storage facility permit. Outreach was an integral part of the project and encompassed any project-related activity that had contact or exposure beyond the project team. The goals of outreach were to foster an environment from which stakeholders could make informed decisions about the project and gauge community receptiveness to a CCUS project. A consistent set of messages and outreach products were developed in conjunction with an outreach advisory board that integrated project partners and team members. To gauge public acceptability of geologically storing CO 2 , 5611 households in the project area were invited to participate in an online survey. The survey results indicate that the public attitude regarding CCUS is neutral to positive, with strong sentiment that CO 2 capture and storage may be an approach to maintain the economic vitality of the region. To achieve project objectives, critical support in the form of financial backing, engineering evaluations, site access, outreach collaboration, operations data, risk assessment/evaluation, and software access was provided by BEPC, the North Dakota Industrial Commission Lignite Research Council, ALLETE Clean Energy, BNI Energy, North American Coal Corporation, Minnkota, Prairie Public Broadcasting, Computer Modelling Group Ltd., and Schlumberger.
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Comparative Economic Analysis of Capture, Transport, and Storage from a CO2 Source Perspective
This presentation provides an overview of a study that evaluated multiple carbon capture and storage (CCS) networks within the Central United States using NETL-developed resources and models to assess management options different CO2 source types face from both economic and regional geologic perspectives when capturing, transporting and storing their CO2. It was presented at the Carbon Capture, Utilization, and Storage (CCUS) 2023 conference, organized and presented by the Society of Petroleum Engineers (SPE), American Association of Petroleum Geologists (AAPG), and Society of Exploration Geophysicists (SEG) and held in Houston, Texas, April 25-27, 2023.
Guinan, Allison↗
A Quantitative Approach for Demonstrating Plume Stabilization Under CCS Policy Frameworks
Conference presentation at Carbon Capture, Utilization, and Storage (CCUS) Conference 2024, Houston, Texas, March 11–13, 2024. The study highlighted the operator’s responsibilities for demonstrating plume stabilization in partial fulfillment of postinjection monitoring and site closure requirements. The metric dA/dt was chosen because of rules and regulations that call out the need to measure the change in area of the plume and plume extents over time. As dA/dt approached dA/dtcritical, the CO 2 plume’s growth was both minimal and predictable. Providing operators with a quantitative approach to determining plume stabilization is important for moving carbon capture and storage (CCS) projects beyond feasibility phases of development.
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PCOR Partnership: A Catalyst for Commercial CCUS Deployment
Conference paper presented at 17th International Conference on Greenhouse Gas Control Technologies (GHGT-17), Calgary, Alberta, Canada, October 20–24, 2024. This paper presents an overview of the Plains CO 2 Reduction (PCOR) Partnership Initiative and the current commercial carbon capture, utilization, and storage (CCUS) activity in the region, discusses challenges facing CCUS in the region, and highlights important challenges that have recently been overcome to enable CCUS deployment in the region.
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